1. Field of the Invention
The present invention is directed towards flowmeters and their use to measure flowrates of different fluids. In particular, the invention relates to the measurement of flowrates in multiphase flow regions.
2. Description of the Related Art
The production of gas in the oil and gas industry in particular is, in most cases, associated with the production of liquid hydrocarbons (that form in the reservoir, in the wellbore and/or at the surface as the pressure and temperature drop), free formation water and condensed vapour. Therefore, from a metering point of view the techniques normally implemented for dry gas metering cannot always be applied.
The measurement of flowrates in multiphase flow regions is difficult, particularly when there is a high to very high gas to liquid ratio. In many applications, particularly in the oil industry, there is a need to measure the gas flowrate directly to assist in the control of gas production. Real time measurement of gas and liquid flowrates are critical in terms of product optimisation, field monitoring and reservoir management. In many deepwater reservoirs, economics may dictate that several fields are joined and processed at a central facility and it is therefore essential that the quantity of gas produced at each well head is known to be able to assign assets to each reservoir.
Wet gas metering can apply to gas condensate fields, high Gas to Oil Ratio (GOR) fields and wet gases (as defined, for example, by reference to the reservoir temperature and cricondotherm of a reservoir fluid). The simplest definition of wet gas is a gas which contains some liquid, more particularly a gas stream with a liquid volume fraction between 5 and 10% at metering conditions. The amount of liquid can vary from a very small of amount of, for example, water to a substantial amount of, for example, a mixture of water and liquid hydrocarbons. The amount and nature of the liquid present and the physical conditions (pressure, temperature, flow rates) all affect flowrate measurements.
Applying this basic definition, wet gas metering can either be seen as the top boundary of multiphase flow metering (oils with high gas volume fractions) or the bottom boundary of gas metering (gases with “high” liquid volume fractions). This implies that by pushing either multiphase flow metering or gas metering to their extremes, wet gas metering solutions could, in theory, be found. However, due to the complexity and peculiarity of wet gas flows, this is not possible.
The occurrence of slip between the liquid and the gas, the difficulties in predicting the transition between flow regimes in horizontal as well as in vertical currents, and the uncertainties related to the PVT characterisation of gas condensate fields are among the problems associated with wet gas metering. In addition to the above, the liquid phase of wet gas streams is frequently a combination of hydrocarbons and water, in which case wet gas metering becomes a problem in three-phases and the oil/water inversion point may have a significant impact on the multiphase flow correlations used to calculate pressure drops and boundaries between flow regimes. Finally, solids may also be present in the stream, so that the problem of wet gas metering extends to four phases.
Attempts are being made across the oil and gas industry to define the boundaries between humid gas, gas-condensate and high GVF (gas volume fraction) multiphase systems. For the different systems, various commercial wet gas meters are known for specific field applications. In some cases, single-phase gas metering devices are used together with “correction factors” to take into account the effect of the liquid present. These devices include orifice plates, inverted venturi (V-cone), venturi tubes, coriolis and ultrasonic meters. Alternatively, elements of multiphase metering technology which were intended for in-line measurements of oil, water and gas streams have been modified to develop wet gas metering systems.
Unfortunately, each of these systems has problems associated with them, particularly at the higher gas volume fractions.
There is therefore a need to provide a metering system which can measure flowrates in multiphase flows at a range of gas volume fractions, particularly higher gas volume fractions.